GEOCHEMISTRY AND ORIGIN OF UPPERCRETACEOUS OILS FROM THE TERMIT BASIN, NIGER

Bang Liu1*, Guangya Zhang1, Fengjun Mao1, Jiguo Liu1 and Mingsheng Lü2

Crude oil samples (n = 16) from Upper Cretaceous reservoir rocks together with cuttings samples of Upper Cretaceous and Paleogene mudstone source rocks (n = 12) from wells in the Termit Basin were characterized by a variety of biomarker parameters using GC and GC-MS techniques. Organic geochemical analyses of source rock samples from the Upper Cretaceous Yogou Formation demonstrate poor to excellent hydrocarbon generation potential; the samples are characterized by Type II kerogen grading to mixed Types II-III and III kerogen. The oil samples have pristane/phytane (Pr/Ph) ratios ranging from 0.73 to 1.27, low C22/C21 and high C24/C23 tricyclic terpane ratios, and values of the gammacerane index (gammacerane/C30hopane) of 0.29-0.49, suggesting derivation from carbonate-poor source rocks deposited under suboxic to anoxic and moderate to high salinity conditions. Relatively high C29 sterane concentrations with C29/C27 sterane ratios ranging from 2.18-3.93 and low values of the regular steranes/17a(H)-hopanes ratio suggest that the oils were mainly derived from kerogen dominated by terrigenous higher plant material. Both aromatic maturity parameters (MPI-1, MPI-2 and Rc) and C29 sterane parameters (20S/(20S+20R) and bb/(aa + bb)) suggest that the oils are early-mature to mature. Oil-to-oil correlations suggest that the Upper Cretaceous oils belongs to the same genetic family. Parameters including the Pr/Ph ratio, gammacerane index and C26/C25 tricyclic terpanes, and similar positions on a sterane ternary plot, suggest that the Upper Cretaceous oils originated from Upper Cretaceous source rocks rather than from Paleogene source rocks. The Yogou Formation can therefore be considered as an effective source rock.

Key words: Termit Basin, Niger, Upper Cretaceous, oil, biomarkers, oil-source correlation, source rocks.

1 Research Institute of Petroleum Exploration and Development, PetroChina, Beijing 100083, China.2 China National Oil and Gas Exploration and Development Corporation, PetroChina, Beijing 100034, China.

* Corresponding author: liubang@petrochina.com.cn

INTRODUCTION

The Termit Basin in SE Niger covers an area of 2.7 × 104 km2 and is a Mesozoic-Cenozoic intracontinental rift which is part of the West and Central African Rift System (WCARS, Fig. 1) (Browne and Fairhead,

1983; Fairhead, 1986; Binks and Fairhead, 1992; Genik, 1993).

A total of 65 oilfields have been discovered in the Termit Basin since the first discovery was made in 1982. Prior to 2014, the reservoirs for most oil discoveries were located in the Paleogene Sokor-1 Formation, except for the oil in the relatively minor ONS-1, YGS-1 and YGW-1 oilfields (Fig. 2a). As more exploration wells were drilled during and after 2014,

195Journal of Petroleum Geology, Vol. 40(2), April 2017, pp 195-207

© 2017 The Authors. Journal of Petroleum Geology © 2017 Scientific Press Ltd

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accumulations began to be discovered in the Upper Cretaceous Yogou Formation at oilfields including KLD-1, KCN-1, KCE-2, KE-2, GRN-1 and SSD-1 located in the southern part of the basin (Fig. 2a). The Yogou Formation contains about 10 % of the basin’s oil reserves. The oil zone ranges in depth from 2060 m to 3330 m (PetroChina, unpublished data).

Upper Cretaceous source rocks with TOC values of 0.36% to 23.32% (average 4.91%) in the upper member of the Yogou Formation are assumed to be the most important source rocks for oils in the basin (Liu et al., 2015). In a previous study (Wan et al., 2014), sixty Paleogene oils from the Termit Basin were analyzed using biomarker distributions and stable carbon isotope compositions, and two oil families were classified by oil-to-oil correlation studies. However, the detailed molecular geochemical characteristics and origin of the Upper Cretaceous oils in the Termit Basin have not yet been investigated in detail.

In the present study, saturated and aromatic biomarker distributions have been determined for the Upper Cretaceous oils in the Termit Basin. These biomarker parameters have been used to investigate the source of the oil, to interpret source rock depositional environment, and to assess the thermal maturity of the source rocks responsible for oil generation. Following oil-oil correlation, the geochemical composition of extracts from Upper Cretaceous source rocks was determined and was compared with that of Upper Cretaceous oils.

GEOLOGICAL BACKGROUND

The NW-SE trending Termit Basin is located between the Tefidet, Tenere, Grein and Kafra grabens (northern Niger) and the Bornu Basin in NE Nigeria (Fig. 1) and extends for about 300 km north-south and 60-110 km west-east. The basin is developed on Precambrian basement and has a graben structure controlled by NW-SE trending border faults (Liu et al., 2015) (Fig. 2b). Development of the Termit Basin was initiated during the break-up of Gondwana and the opening of the South Atlantic starting at about 130 Ma (Faure, 1966; Burke et al., 1972; Olade, 1975; Burke, 1976; Petters, 1978, 1981; Genik, 1993). Rifting in the Termit and nearby grabens in the early to late Albian resulted in rapid subsidence and the deposition of fluviatile to lacustrine sediments (Schull, 1988; Bosworth, 1992; Genik, 1993; Zanguina et al., 1998; Liu et al., 2012). Thus Lower Cretaceous fluvial and lacustrine mudstones and sandstones in the Termit Basin are up to 2500 m thick (Liu et al., 2015) (Fig. 2b Fig. 3).

Post-rift thermal subsidence in the Termit Basin took place during the Late Cretaceous. A major change in palaeogeographic setting occurred during the Cenomanian with marine incursions into the Niger and Chad Basins via narrow seaways both to the north (i.e. from the Neo-Tethys) and the south (i.e. from the South Atlantic via the Benue Trough) (Philip et al., 1993a, 1993b; Guiraud et al., 2005). In the Termit Basin, thick shallow-marine to paralic sandstones and

Fig.1. Regional map of the West and Central African Rift System with the location of the Termit Basin in eastern Niger (modified from Genik, 1993).

National frontier

196 Geochemistry of Upper Cretaceous oils from the Termit Basin, Niger

Liu Bang.indd 196 06/03/2017 15:06:37

mudstones were deposited (Liu et al., 2015). The Upper Cretaceous succession here is divided into the Donga (Cenomanian – Coniacian) and Yogou (Santonian and Campanian) Formations (Fig. 2b, Fig. 3).

A regression during the Maastrichtian accompanied by epeirogenic deformation led to an infl ux of detrital material with the deposition of fl uvial sandstones grading upwards into a sandy braided system (Zanguina et al., 1998) known as the Madama Formation (Fig. 2b, Fig. 3).

A second phase of rifting from the Paleocene to the middle Eocene occurred in the grabens in eastern Niger and resulted in deposition of the Paleocene – Eocene Sokor-1 Formation sandstones. Early Oligocene synrift lacustrine mudstones in the Termit Basin are known as the Sokor-2 Formation. Thermal subsidence in

the Miocene and Pliocene was accompanied by the deposition of coarse continental clastics (Liu et al., 2015) (Fig. 2b, Fig. 3).

MATERIALS AND METHODS

Materials used in this study consist of sixteen crude oil samples from the Upper Cretaceous Yogou Formation, and twelve cuttings samples from the Paleogene Sokor-1 Formation and the Upper Cretaceous Yogou Formation mudstones in the Termit Basin. The locations of the sampled wells are shown in Fig. 2a.

Organic geochemical analyses were performed in the State Key Laboratory of Petroleum Resources and Prospecting in the China University of Petroleum. Cuttings samples were prepared following the

Fig.2a (right). Map of the Agadem permit area in the Termit Basin showing the locations of the sampled wells.Fig.2b (below). SE-NW structural cross-section across the Termit Basin showing the rift architecture (location of cross-section in Fig. 2a).

N + Q

Sokor 2

Sokor 1

Madama

Yogou

Donga

K 1

BasementBasement

0

1000

2000

3000

4000

5000

6000

0

1000

2000

3000

4000

5000

6000

KCE-2

KCN-1 KE-2

KLD-1

SSD-1

YGW-1

GGR-1 YGS-1

ONS-1

DD-3DBL-1

A

A’

wells sampled for this study

a

N

0 10 20 km

N I G E R

Nigeria

Algeria

Chad

Mali

Agadem

Niamey

197B. Liu et al.

Liu Bang.indd 197 06/03/2017 15:06:38

procedures described in detail by Liu et al. (2015). GC and GC-MS analyses of the saturated and aromatic hydrocarbon fractions were performed on an Agilent 5975i GC-MS system equipped with an HP-5 MS (5%-phenyl-methylpolysiloxane) fused silica capillary column (60 m×0.25 mm i.d., with a 0.25 μm film thickness). The GC operating conditions were as follows: for the saturated faction, the GC oven temperature was held initially at 50 °C, ramped

to 120 °C at 20 °C/min, then to 310 °C at 3 °C/min, and then kept isothermal for 25 min; for the aromatic fraction, the temperature was held initially at 80 °C for 1 min, ramped to 310 °C at 3 °C/min, and then kept isothermal for 16 min. Helium was used as the carrier gas. The injector temperature was set to 300 °C. The MS was operated in the electron impact (EI) mode with ionization energy of 70 eV, and a scan range of 50-600 Da.

Fig. 3. Generalized stratigraphic column for the Termit Basin (modified from Genik, 1993).

198 Geochemistry of Upper Cretaceous oils from the Termit Basin, Niger

Liu Bang.indd 198 06/03/2017 15:06:38

RESULTS

Bulk properties of crude oilsBulk properties for the studied crude oils are presented in Table 1. The oils have relatively high API gravity (21.3-44.5). The relative abundance of saturated hydrocarbons suggests that the oils are predominantly aliphatic. In addition, all the studied oils have saturated/aromatic ratios > 2 and there was no sign of biodegradation. The oils are characterized by a relatively high abundance of n-C21 to n-C31 n-alkanes in the saturated factions, indicating high waxiness which is confirmed by the ∑(C21– C31) / ∑(C15– C20) ratio which ranges from 0.80-1.57 (average 1.02).

n-Alkanes and isoprenoidsGas chromatographic data for n-alkanes and isoprenoids are presented in Table 2. A chromatogram of the saturated fraction from a representative oil sample (YGW01) is shown in Fig. 4. n-Alkanes in the oil samples are generally in the C11-C32 range and maximize between n-C15 and n-C21. The majority of the oil samples have a unimodal n -alkane distribution dominated by lower molecular weight components. The C21-/C21+ ratios of most samples are 1 to 2.14 with the exception of samples YGS02, YGW01 and YGW03 which have lower values (0.89-0.98: Table 2).

Values of the carbon preference index (CPI) and odd-over-even predominance (OEP) range from 0.97 to 1.12 and 1.01-1.15, respectively (Table 2). Pr/Ph ratios range from 0.73 to 1.27, averaging 0.94. Pr/n-C17 and Ph/n-C18 ratios range from 0.09-0.53 and 0.08-0.84, respectively (Table 2).

TerpanesThe distributions and relative abundances of tricyclic, tetracyclic and pentacyclic terpanes obtained from

m/z 191 ion chromatograms are given in Fig. 5 and their parameters are summarized in Table 3. The oil samples show that the abundance of C29 hopanes is generally one-half or less than that of the C30 hopanes and that the C29/C30 17a (H) hopane ratio is less than 1 (0.42-0.73) (Table 3, Fig. 5). The gammacerane index (gammacerane/C30 hopane) varies from 0.29 to 0.49. The C22/C21, C24/C23 and C26/C25 tricyclic terpane ratios of the oil samples range from 0.18-0.72, 0.56-0.85 and 1.34-2.27, respectively (Table 3).

SteranesMass chromatograms (m/z 217) show that the oil samples are dominated by C29 regular steranes over C27 and C28 isomers, with the ratios of C27/C29 steranes varying from 0.25 to 0.46 (Table 3, Fig. 6). The oil samples have ratios of 20S/(20S+20R) regular steranes and ββ/(αα+ββ) for C29 of 0.20-0.53 and 0.18-0.44, respectively. Regular steranes/17α-hopanes ratios vary from 0.15 to 0.83 (Table 3).

AromaticsMolecular parameters of aromatic hydrocarbons are shown in Table 3. The methylphenanthrene index (MPI-1) for the oil samples ranges from 0.2 to 0.98. These values calculated to vitrinite reflectance (Rc) range from 0.49% to 0.96%. MPI-2 values for the majority of oil smaples vary from 0.23 to 0.72, with the exception of one sample (ONS01) which has a value of 1.05 (Table 3).

DISCUSSION

Lithology and depositional environmentsThe crude oils listed in Table 2 and Table 3 were examined using aliphatic biomarker parameters to investigate source rock lithology and depositional

Table 1. Bulk composition of crude oil samples from the Termit Basin.

Crude oil API Saturate Aromatic Resins Asphalt- Saturate/ ∑(C21–C31)/sample gravity (o) hcs % hcs % (%) enes (%) Aromatic ∑(C15–C20)

KLD-1 KLD01 L. Cretaceous 44.5 79.09 16.92 2.46 1.54 4.67 0.90KCN01 L. Cretaceous 24.8 55.17 24.37 14.25 6.20 2.26 1.12KCN02 L. Cretaceous 40.2 78.05 14.63 5.77 1.55 5.34 0.81KCE01 L. Cretaceous 29.1 77.31 15.50 5.17 2.02 4.99 0.96KCE02 L. Cretaceous 28.3 74.94 15.80 8.13 1.13 4.74 0.98KCE03 L. Cretaceous 41.2 69.22 23.08 4.40 3.30 3.00 0.95

KE-2 KE01 L. Cretaceous 21.3 64.33 11.19 5.25 19.23 5.75 0.80GRN01 L. Cretaceous 27.8 75.23 14.87 9.01 0.90 5.06 0.80GRN02 L. Cretaceous 29.4 55.85 22.08 20.56 1.51 2.53 0.80

SSD-1 SSD01 L. Cretaceous 29.2 0.82ONS-1 ONS01 L. Cretaceous 31.8 58.57 12.15 11.60 17.68 4.82 1.01

YFS01 L. Cretaceous 40.0 60.76 19.62 13.40 6.22 3.10 1.11YFS02 L. Cretaceous 23.0 49.25 20.90 16.42 13.43 2.36 1.57

YGW01 L. Cretaceous 37.0 55.25 16.89 16.44 11.42 3.27 1.38YGW02 L. Cretaceous 36.6 68.37 10.86 11.50 9.27 6.30 0.95YGW03 L. Cretaceous 34.7 56.70 17.01 20.62 5.67 3.33 1.38

Reservoir age

KCE-2

GRN-1

YGS-1

YGW-1

Oilfield

KCN-1

199B. Liu et al.

Liu Bang.indd 199 06/03/2017 15:06:38

Fig.4. Gas chromatography trace of a representative oil sample (YWG01) from the Termit Basin. Numbers along the top indicate the number of carbon atoms in the n-alkanes; Pr = pristane; Ph = phytane.

Table 2. Gas chromatogram data of n-alkanes and acyclic isoprenoids of the oil samples from the Termit Basin.

a: nC21-/nC22+: ratio of C21-n-alkanes / C22+n-alkanes,b: Pr/Ph: pristane/phytane ratio; c: Pr/n-C17: pristane/n-C17 alkanes ratio; d: Ph/n-C18: phytane/n-C18 alkanes ratioe: CPI: carbon preference index;f: OEP: odd-even predominance.

Max. nC21-/nC22+ Pr/Ph Pr/n-C17 Ph/n-C18 CPI OEP peak a b c d e f

KLD-1 KLD01 C17 1.27 1.27 0.16 0.15 1.06 1.08KCN01 C17 1.00 0.82 0.21 0.29 1.11 1.11KCN02 C15 1.68 1.11 0.10 0.10 1.08 1.14KCE01 C17 1.28 1.09 0.09 0.08 1.09 1.14KCE02 C17 1.26 1.18 0.09 0.08 1.10 1.13KCE03 C17 1.27 1.19 0.09 0.08 1.08 1.15

KE-2 KE01 C17 1.61 1.16 0.10 0.10 1.08 1.11GRN01 C17 1.62 0.76 0.21 0.29 1.12 1.07GRN02 C17 1.56 0.74 0.20 0.30 1.13 1.05

SSD-1 SSD01 C17 2.10 0.77 0.35 0.63 1.04 1.01ONS-1 ONS01 C17 2.14 0.83 0.53 0.84 1.11 1.13

YGS01 C19 1.21 0.81 0.20 0.24 1.03 1.02YGS02 C21 0.89 0.85 0.34 0.34 0.97 1.15YGW01 C19 0.97 0.81 0.19 0.20 1.06 1.02YGW02 C17 1.39 0.90 0.19 0.22 1.06 1.10YGW03 C19 0.98 0.73 0.21 0.25 1.01 1.01

Oilfields Crude oils

KCE-2

GRN-1

YGW-1

YGS-1

KCN-1

200 Geochemistry of Upper Cretaceous oils from the Termit Basin, Niger

Liu Bang.indd 200 06/03/2017 15:06:39

setting. The Pr/Ph ratio is widely used as an indicator of the redox potential of the depositional environment (Powell and McKirdy, 1973; Didyk et al., 1978; Tissot and Welte, 1984). High Pr/Ph values (>3.0) indicate oxic conditions, and low values (<1) indicate anoxic conditions (Powell, 1988; Peters and Moldowan, 1993). Pr/Ph ratios for the oil samples range from 0.73 to 1.27 (Table 2), suggesting that the oils were derived from source rocks deposited under suboxic to anoxic conditions.

The C22/C21 and C24/C23 tricyclic terpanes ratios can be used to identify extracts and crude oils derived from carbonate source rocks. Oil from carbonate-rich source rocks can be distinguished by high C22/C21 and low C24/C23 tricyclic terpane ratios (Peters et al., 2005). The low C22/C21 (0.18-0.72) and high C24/C23 tricyclic terpanes (0.56-0.85) in the samples analysed suggested that they were generated by carbonate-poor source rocks (Fig. 7).

Gammacerane is an indicator of water column stratification which commonly occurs in hypersaline settings (Sinninghe Damsté et al., 1995), and the gammacerane index is used to measure the relative prominence of gammacerane. The gammacerane index varies from 0.29-0.49 (Table 3), indicating a moderate to high salinity in the depositional setting.

Source of organic matterSteranes are valuable as indicators of organic matter type in source rocks (Peters and Moldowan, 1993). C27 sterols predominate in marine organic matter, whereas C29 sterols predominate in terrigenous organic matter (Huang and Meinschein, 1979). A ternary diagram (Fig. 8) and reprensentative mass chromatograms (m/z 217, Fig. 6) show that steranes present in the oil samples are dominated by C29 regular steranes over C27 and C28 isomers. The C29/C27 sterane ratio ranges from 2.18 to 3.93 (Table 3). These molecular biomarkers suggest that the crude oils are mainly derived from kerogen dominated by terrigenous higher plant material.

The ratio of regular steranes/17a(H)-hopanes indicates the input of eukaryotic (mainly algal and higher plant) versus prokaryotic (bacterial) material to the source rock (Chakhmakchev et al., 1996). The sterane/hopane ratio is relatively high in marine organic matter, with values generally approaching unity or even higher. In contrast, low steranes and sterane/hopane ratios are indicative of terrigenous and/or microbially reworked organic matter (Chakhmakchev et al., 1996). The n-alkanes profile and the absence of UCM (unresolved complex mixture) indicate the non-biodegraded nature of the oil samples. Thus, the low value of the regular steranes/17α(H)-hopanes ratio (0.15-0.83, averaging 0.41) of the oil samples (Table 3) is interpreted to indicate the high contribution of terrigenous organic matter in the source rock. G

am in

dex:

gam

mac

eran

e in

dex;

T

T C

22/C

21:

tric

yclic

ter

pane

C22

/C21

; TT

C26

/C25

: tri

cycl

ic t

erpa

ne C

26/C

25;

Reg

ular

Ste

r/17

a-H

op: r

egul

ar s

tera

nes/

17a

-hop

anes

;bb

/ (a

a+b

b) C

29-S

ter:

bb/

(aa

+bb)

C29

-ste

rane

s; 2

0S/(

20S+

20R

) C

29-S

ter:

20S

/(20

S+20

R)

C29

ste

rane

s; M

P: m

ethy

lphe

nant

hren

es;

M

PI-

1 =

1.5

* (M

P +

3-M

P)

/ (P

+1 -

MP

+9 -

MP

); M

PI-

2 =

3 *

(2-M

P)

/ (P

+1- M

P+9

- M

P);

Rc(

%)

= 0.

4 +

0.6

* (M

PI-

1).

Tabl

e 3.

Ste

rane

par

amet

ers

(m/z

217

chr

omat

ogra

ms)

, hop

ane

indi

ces

(m/z

191

chr

omat

ogra

ms)

and

aro

mat

ic h

ydro

carb

on m

atur

ity

para

met

ers

of t

he o

il sa

mpl

es

from

the

Ter

mit

Bas

in.

Regu

lar s

tera

nes

C27

C28

C29

Regu

lar s

ter/

ββ/(

αα+β

β)20

S/(2

0S+2

0R)

C29/

C27

ster

anes

(%)

ster

anes

(%)

ster

anes

(%)

17α-

Hop

C29-s

ter

C29-s

ter

KLD-

1KL

D01

0.33

0.40

0.80

1.52

2.18

24.3

622

.48

53.1

60.

150.

400.

400.

530.

560.

69KC

N01

0.45

0.33

0.66

1.48

3.34

18.2

320

.87

60.9

00.

370.

280.

340.

410.

500.

61KC

N02

0.34

0.51

0.66

1.63

3.09

19.0

422

.19

58.7

70.

200.

330.

360.

480.

550.

66KC

E01

0.37

0.72

0.67

2.01

2.87

19.5

024

.51

55.9

80.

310.

220.

280.

400.

470.

61KC

E02

0.31

0.18

0.63

2.06

2.81

20.0

923

.39

56.5

20.

320.

220.

270.

460.

520.

64KC

E03

0.33

0.32

0.63

1.53

2.83

19.7

124

.58

55.7

10.

250.

260.

330.

380.

430.

60KE

-2KE

010.

320.

380.

741.

672.

4822

.22

22.7

655

.02

0.16

0.35

0.37

0.61

0.63

0.74

GRN

010.

490.

390.

641.

343.

4318

.26

19.1

162

.63

0.31

0.23

0.24

0.34

0.42

0.57

GRN

020.

420.

460.

651.

593.

1419

.49

19.2

061

.30

0.34

0.25

0.23

0.39

0.46

0.61

SSD-

1SS

D01

0.34

0.38

0.76

1.41

3.93

15.6

922

.59

61.7

20.

510.

320.

380.

200.

230.

49O

NS-

1O

NS0

10.

360.

410.

851.

922.

8919

.44

24.4

756

.10

0.34

0.44

0.53

0.98

1.05

0.96

YGS0

10.

300.

320.

612.

053.

4617

.61

21.3

861

.00

0.51

0.21

0.31

0.67

0.72

0.77

YGS0

20.

300.

300.

702.

273.

2418

.42

21.9

959

.59

0.61

0.18

0.25

0.53

0.59

0.69

YGW

010.

440.

390.

632.

133.

2118

.38

22.6

458

.98

0.74

0.21

0.22

0.60

0.67

0.73

YGW

020.

290.

370.

671.

713.

1718

.87

21.3

959

.74

0.59

0.26

0.23

0.44

0.53

0.64

YGW

030.

470.

360.

562.

093.

4017

.57

22.6

659

.77

0.83

0.18

0.20

0.56

0.64

0.70

KCN

-1

KCE-

2

GRN

-1

YGS-

1

YGW

-1

MPI

-1M

PI-2

RcTT

C26

/C25

Wel

lsSa

mpl

e N

o.G

am in

dex

TT C

22/C

21TT

C24

/C23

201B. Liu et al.

Liu Bang.indd 201 06/03/2017 15:06:39

Thermal maturityParameters based on aromatic hydrocarbons can be used for the evaluation of thermal maturity. MPI-1 is useful to calculate vitrinite reflectance, Rc (Radke et al., 1982, 1983; Radke, 1988). The MPI-1 and calculated Rc are 0.20-0.98 and 0.49-0.96%, respectively (Table 3). The Rc for the majority of oil samples suggests maturities equivalent to early to peak oil generation (0.49-0.77), while sample ONS01 has a late oil generation window maturity (>0.98% Rc) (cf. Radke, 1987).

The following classification of oils has been proposed based on the MPI-2 index: high maturity: MPI-2 >2; moderate maturity: MPI-2 = 0.8-1.0; and low maturity: MPI-2 < 0.8 (Angelin et al., 1983; Radke, 1987; Ivanov and Golovko, 1992). Except for one sample (ONS01), the low values of MPI-2 (0.23-0.72) for the majority of the oils are interpreted to indicate low maturities. By contrast, the high value of MPI-2 in oil sample ONS01 (1.05) suggests a moderate level of thermal maturity (Table 3).

The CPI and OEP have been used to estimate thermal maturity (Bray and Evans, 1961; Scalan and Smith, 1970). Values significantly above or below 1.0, respectively, indicate thermally immature organic matter, whereas values of 1.0 are typical of thermally mature oil or source rock extracts (Peters and Moldowan, 1993). The CPI and OEP values of

the oil samples range from 0.97-1.12 and 1.01-1.15, respectively (Table 2), suggesting an early mature to mature stage.

The 20S/(20S+20R) and ββ/(αα+ββ) isomerization ratios of the C29 steranes, whose equilibrium values are 0.52-0.55 and 0.67-0.71, can be used as indicators of maturity (Seifert and Moldowan, 1986). For the oil samples, 20S/(20S+20R) and ββ/(αα+ββ) C29 steranes range from 0.20-0.53 and 0.18-0.44, respectively (Table 3). All the oil samples had values which are well below the equilibrium values of these parameters, suggesting that they have early oil window maturities. According to a cross-plot of 20S/(20S+20R) versus ββ/(αα+ββ) C29 steranes, most of the samples (except three) plot in the early mature to mature zone (Fig. 9).

Oil-oil and oil-source rock correlationGood oil-oil correlation is indicated by the presence of nearly identical biomarker fringerprints in m/z 191 and m/z 217 mass chromatograms (Fig. 5, Fig. 6.). The Upper Cretaceous oils have similar C22/C21 and C24/C23 tricyclic terpane ratios and C29/C30 and C35/C34 hopane ratios (0.18-0.72, 0.56-0.85, 0.42-0.73, and 0.47-0.75, respectively; Table 4), suggesting that these oils belongs to the same genetic family. This conlcusion is further supported by a ternary diagram of regular C27, C28, C29 steranes on which the oils cluster tightly (Fig. 8).

Fig. 5. Mass chromatograms (m/z 191) showing the distribution of tricyclic, tetracyclic and pentacyclic terpanes for reprensentative oil and mudstone samples from the Termit Basin. Numbers with H (29H-35H) indicate hopanes; Ts: 18a(H)-22,29,30-trisnorneohopane; Tm: 17a(H)-22,29,30-trisnorhopane; C29Ts: 18a(H)-30-norneohopane.

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Fig. 6. Mass chromatograms (m/z 217) showing the distribution of steranes for reprensentative oil and mudstone samples from the Termit Basin. Key to labels: Peak 1: C27aaa sterane (20S); Peak 2: C27abb sterane (20R); Peak 3: C27abb sterane (20S); Peak 4: C27aaa sterane (20R); Peak 5: C28aaa sterane (20S); Peak 6: C28abb sterane (20R); Peak 7: C28abb sterane (20S); Peak 8: C28aaa sterane (20R); Peak 9: C29aaa sterane (20S); Peak 10: C29abb sterane (20R); Peak 11: C29abb sterane (20S); Peak 12: C29aaa sterane (20R).

Table 4. Sterane parameters (m/z 217 chromatograms) and hopane indices (m/z 191 chromatograms) of the Upper Cretaceous Yogou source rocks from the Termit Basin.

Gammacerane C26/C25 tricyclic C27/C29

index terpane ratios steranes C27 (%) C28 (%) C29 (%)Dbl-1 2697 0.83 0.48 1.58 0.48 24.57 23.95 51.48Dbl-1 2746 0.69 0.51 1.41 0.30 18.43 19.70 61.88Dbl-1 2822 0.63 0.50 1.23 0.50 25.17 24.42 50.41Dbl-1 2850 1.29 0.28 1.96 0.51 25.06 25.62 49.32Dbl-1 2913 1.20 0.38 1.92 0.45 23.57 23.54 52.89Dbl-1 3106 1.14 0.40 1.67 0.46 23.86 24.07 52.07DD-3 2388 1.18 0.09 2.16 0.41 18.26 36.68 45.06DD-3 2644 0.91 0.14 2.38 0.89 32.52 31.07 36.41DD-3 2828 2.09 0.16 2.05 0.85 32.78 28.44 38.78DD-3 2988 1.93 0.07 2.13 0.97 35.53 27.76 36.71DD-3 3020 1.86 0.13 3.13 0.82 31.34 30.34 38.33DD-3 3122 0.67 0.14 2.10 0.87 31.86 31.56 36.58

Regular steranesWells Depth Pr/Ph

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Source rock parameters (TOC, Rock-Eval) and biomarker data for the Upper Cretaceous Yogou and Donga Formation from eight wells in the Termit Basin were presented by Liu et al. (2015). A summary of TOC and Rock-Eval data for the Yogou and Donga Formations are presented in Table 5. The source rock potential of the Yogou and Donga Formations was evaluated from TOC and pyrolysis S2 yields. The Yogou mudstones have TOC values of 0.36-23.32 % (average 2.59 %) and pyrolysis S2 yields of 0.15-70.15 mg/g (average 5.59 mg/g), indicating variable (poor to excellent) hydrocarbon generation potential. HI and Tmax values indicate that most samples from the Yogou Formation contain Type II kerogen grading to

mixed Type II-III and Type III kerogen. TOC values for the Donga mudstones range from 0.42 % to 1.47 %, averaging 0.89 %, and S2 yields range from 0.29 to 2.8 mg/g, averaging 1.1 mg/g. Although a minority of the Donga mudstones have good hydrocarbon potential, the majority have poor to fair hydrocarbon potential. HI and Tmax values suggest that samples from the Donga Formation mainly contain Type III kerogen.

Petrographic analyses of the Upper Cretaceous samples show that organic matter is dominated by terrigenous higher plant material with vitrinite, inertinite and specific liptinites, and extracts are characterized by a predominance of C29 steranes over C27 and C28 homologues. The organic matter in the

Fig. 7. Cross-plot of C22/C21 versus C24/C23 tricyclic terpanes for oil samples from the Termit Basin.

Fig.8. Sterane ternary plot for oils and Upper Cretaceous Yogou and Paleogene source rock samples from the Termit Basin.

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Upper Cretaceous succession is interpreted mainly to be derived from terrigenous higher plants (Liu et al., 2015).

To investigate the genetic link between the studied oils and potential source rocks, molecular parameters were used for correlation. Figs 4, 5 and 6 show gas chromatographs and m/z 191 and m/z 217 chromatograms of a representative mudstone sample from the Termit Basin. In general the oil data closely match the Upper Cretaceous marine source rock data, and is different from the Paleogene lacustrine source rock data. Key similarities include the closely similar values of the Pr/Ph ratios, gammacerane index, C26/C25 tricyclic terpanes and C27/C29 steranes, and the similar positions on the sterane ternary plot (Fig. 8).

The samples from the Upper Cretaceous Yogou Formation have Pr/Ph ratios of 0.63-1.29, C26/C25 tricyclic terpane ratios of 1.41-1.96, abundant C29 steranes, C27/C29 sterane ratios of 0.30-0.51, and a gammacerane index of 0.28-0.51. By contrast, the Paleogene samples have Pr/Ph ratios of 0.67-2.09, C26/C25 tricyclic terpane ratios of 2.05-3.13, a relatively higher abundance of C27 steranes, C27/C29 sterane ratios ranging from 0.41-0.97, and a gammacerane index of

0.07-0.14 (Table 4). The data for the Upper Cretaceous Yogou Formation source rocks are relatively consistent with the observations for the Upper Cretaceous oils described above, indicating that the oils were sourced from Upper Cretaceous source rocks rather than Paleogene source rocks. This conclusion is further supported by the sterane ternary plot (Fig. 8). As described above, mudstones from the Upper Cretaceous Yogou Formation are mainly mature and have poor to excellent potential to generate oil and gas, whereas mudstones from the Upper Cretaceous Donga Formation are dominated by Type III organic matter with poor to fair hydrocarbon potential to produce gas. Therefore, the Yogou Formation can be considered as an effective source rock.

Molecular geochemical parameters and stable carbon isotope compositions indicate that the majority of the Paleogene oils were probably sourced from saline, reducing marine source rocks (Wan et al., 2014). Biomarker distributions of the Paleogene oils are similar to those of the Upper Cretaceous oils, suggesting that the oils from the two formations belong to the same genetic family and probably contain the same source organic materials. Oil generated from

Fig. 9. Cross-plot of 20S/(20S+20R) vesus bb/ (bb+aa) C29 steranes for oil samples from the Termit Basin.

Table 5. Summary of TOC and Rock-Eval data for the Yogou and Donga Formations from the Termit Basin.

C29 ββ/(ββ +αα)

C29

20S

/(20S

+20

R)

Immature

Low mature

Mature

cuttings 0.36-23.32 0.15-70.15 29.00-822.08 423-447 & SWC (av. 2.59) (av. 5.59) (av. 192.06) (av. 436)

0.42-1.47 0.29-2.81 47.54-208.96 431-456 (av. 0.89) (av. 1.11) (av. 118.45) (av. 443)

Donga cuttings mudstone

HI (mg/g) Tmax (°C)

Yogou mudstone

Formation Sample type Lithology TOC % S2 (mg/g)

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the Upper Cretaceous source rocks migrated into the Paleogene reservoirs through faults.

The highest sea-levels in the Phanerozoic eon occurred during the Late Cretaceous (Hancock and Kauffman, 1979). In the Late Cretaceous, a marine transgression formed a large-scale basin (encompassing the Benue Trough, Bornu Basin, Termit Basin and Tenere Basin) in which thick, shallow-marine to paralic sediments were deposited (Gebhardt, 1997; Liu et al., 2011; Adegoke et al., 2014; Boboye and Nzegwu, 2014; Alalade, 2016). The Upper Cretaceous succession in the Tenere Basin, Termit Basin, Benue Trough and Bornu Basin is therefore part of a regionally extensive shallow marine-paralic depositional system. These Upper Cretaceous shallow marine-paralic deposits can be considered as an important source rock for hydrocarbons in the basins affected by the Late Cretaceous marine incursion.

CONCLUSIONS

In all, 16 oils and 12 source rock extracts were analyzed to investigate the compositional characteristics and origin of Upper Cretaceous oils in the Termit Basin. The geochemical composition of the oils indicates generation from carbonate-poor source rocks deposited under sub-oxic to relatively anoxic and moderate to high salinity conditions. Molecular biomarkers suggest that the oils are mainly derived from kerogen dominated by terrigenous higher plant material. Biomarker maturity parameters indicate that the oils are at a relatively low level of thermal maturity. Oil-to-oil correlations suggest that the Upper Cretaceous oils belong to a single genetic family. Oil-to-source correlations demonstrate that the oils are sourced from Upper Cretaceous source rocks rather than Paleogene source rocks.

ACKNOWLEDGEMENTS

This study was supported by the National Science and Technology Major Project of China (No. 2016ZX05029005). The authors acknowledge the assistance of CNPC Niger Petroleum S.A. for granting permission to analyse the oil and source rock samples. The authors are also grateful for the analytical assistance of Shengbao Shi and Lei Zhu of the China University of Petroleum. Journal reviews of a previous version by Dr Moussa Harouna and Professor R. Littke are acknowledged with thanks.

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